CO-GASIFICATION OF MICROALGAE BIOMASS AND LOW-RANK COAL TO PRODUCE SYNGAS/HYDROGEN
A process and apparatus for producing syngas from low grade coal and from a biomass wherein the process includes (i) gasification of a mixture of low grade coal and biomass, (ii) reforming the gasified mixture, and (iii) removing CO2 from the gasified and reformed syngas mixture.
Latest King Fahd University of Petroleum and Minerals Patents:
Adnan, M. A., Hossain, M. M. (2018), Co-gasification of Indonesian coal and microalgae A thermodynamic study and performance evaluation, Chemical Engineering and Processing—Process Intensification, 128 (2018), Pages 1-9 (Accepted 1 Apr. 2018, Available online 3 Apr. 2018.) which is incorporated by reference for all purposes.BACKGROUND OF THE INVENTION Field of the Invention
The invention pertains to the field of chemical engineering, more specifically to gasification of low grade coal and algae biomass to produce syngas.Description of Related Art
The increase of fossil fuel combustion associated with the growth of industrial activities contributes to huge amounts of CO2 release into the surroundings. The excess quantity of CO2 emission is thought to contribute to severe environmental problems such as climate change and global warming. See de Lasa H, Salaices E, Mazumder J, Lucky R. Catalytic Steam Gasification of Biomass: Catalysts, Thermodynamics and Kinetics. Chem Rev 2011; 111:5404, incorporated herein by reference in its entirety. The climate anomalies threaten the sustainability of the human being and other ecosystems.
In order to limit the harmful effects of fossil fuel combustion while maintaining the industrial and economic growths, communities have been working on development of renewable energy resources and advanced energy conversion technologies. Biomass from different sources including both terrestrial and aquatic plants has been considered as a sustainable renewable energy source due to their abundant availability with a minimum cost. See Sansaniwal S K, Rosen M A, Tyagi S K. Global challenges in the sustainable development of biomass gasification: An overview. Renew Sust Energ Rev 2017; 80:23, incorporated herein by reference in its entirety. Recently, some aquatic biomasses, particularly micro- and macro-algae, have received growing interest because of their high productivity, easy cultivation, and ability to recycle CO2 by photosynthetic processes. The combustion of these aquatic biomasses also emits minimum amounts of SOx, as their sulfur content is lower than that found in fossil fuels. See Razzak S A, Hossain M M, Lucky R A, Bassi A S, de Lasa H. Integrated CO2 capture, wastewater treatment and biofuel production by microalgae culturing—A review. Renew Sust Energ Rev 2013; 27:622; and Razzak S A, Ali SAM, Hossain M M, deLasa H. Biological CO2 fixation with production of microalgae in wastewater—A review. Renew Sust Energ Rev 2017; 76:379, each incorporated herein by reference in their entirety.
For several years, research has been focused on microalgae to biodiesel production technologies by extracting the lipid from the microalgae cells. See Chisti Y. Biodiesel from microalgae. Biotechnology Advances 2007; 25:294, incorporated herein by reference in its entirety. Recently, thermochemical processes including gasification and combustion are gaining more attention due to their high conversion efficiency. See Adnan M A, Susanto H, Binous H, Muraza O, Hossain M M. Feed compositions and gasification potential of several biomasses including a microalgae: A thermodynamic modeling approach. Int J Hydrogen Energy 2017; 42:17009; Adnan M A, Hossain M M. Gasification of various biomasses including microalgae using CO2—A thermodynamic study. Renew Energ 2018; 119:598; and Qadi N M N, Hidayat A, Takahashi F, Yoshikawa K. Co-gasification kinetics of coal char and algae char under CO2 atmosphere. Biofuels 2017; 8:281, each incorporated herein by reference in their entirety. The produced gas (usually referred to as syngas) can be used in various applications including fuel gas, power generation, and feedstock for other chemical industries such as methanol, fertilizer, etc.
On the other hand, coal plays a significant role meeting the global energy demand. Around 40% of global electricity demand is currently being met by coal combustion. See Khatami R, Levendis Y A. An overview of coal rank influence on ignition and combustion phenomena at the particle level. Combustion and Flame 2016; 164:22, incorporated herein by reference in its entirety.
Coals are classified into various ranks according to their combustion quality. With ever increasing energy demand, the focus is shifting to low-rank coal despite limitations which include low heating value, high moisture content and high CO2 emissions.
In addition, in some countries including Indonesia and China, low-rank (lignite and sub-bituminous coal) coal is abundantly available as compared to the high-rank coal. See Tahmasebi A, Zheng H, Yu J. The influences of moisture on particle ignition behavior of Chinese and Indonesian lignite coals in hot air flow. Fuel Process Technol 2016; 153:149, incorporated herein by reference in its entirety.
For combustion in a pulverized coal combustor, low-rank coal requires additional treatment to deal with excessive moisture content. In some applications, high-temperature exhaust gas is used in thermal drying for removing moisture from low-rank coal. However, these additional treatments undermine the overall efficiency of the power plant. See Xu C, Xu G, Zhao S, Zhou L, Yang Y, Zhang D. An improved configuration of lignite pre-drying using a supplementary steam cycle in a lignite fired supercritical power plant. Appl Energ 2015; 160:882, incorporated herein by reference in its entirety.
In this regard, the gasification followed by combustion of the gasified products is considered as an efficient and environmental friendly approach for utilization of low-rank coal. See Zhang L, Kajitani S, Umemoto S, Wang S, Quyn D, Song Y, et al. Changes in nascent char structure during the gasification of low-rank coals in CO2. Fuel 2015; 158:711, incorporated herein by reference in its entirety. However, presence of moisture in other low-rank coal gasification mixtures can facilitate rather than diminish the gasification process.
In view of the problems associated with gasification of low rank coal, many studies have been directed to investigate and identify suitable parameters to enhance the gasification performance of low-rank coal into usable energy; Duan W, Yu Q, Liu J, Wu T, Yang F, Qin Q. Experimental and kinetic study of steam gasification of low-rank coal in molten blast furnace slag. Energy 2016; 111:859; Xiao Y, Xu S, Song Y, Wang C, Ouyang S. Gasification of low-rank coal for hydrogen-rich gas production in a dual loop gasification system. Fuel Process Technol 2018; 171:110; and Fan S, Xu L-H, Kang T-J, Kim H-T. Application of eggshell as catalyst for low rank coal gasification: Experimental and kinetic studies. Journal of the Energy Institute 2017; 90:696, each incorporated herein by reference in their entirety.
Recently, the use of CO2 in biomass/coal gasification is gaining increasing interest due to the opportunity utilization of this greenhouse gas in the gasification process. See Adnan et al. (2018); Soreanu G, Tomaszewicz M, Fernandez-Lopez M, Valverde J L, Zuwala J, Sanchez-Silva L. CO2 gasification process performance for energetic valorization of microalgae. Energy 2017; 119:37; and Billaud J, Valin S, Peyrot M, Salvador S. Influence of H2O, CO2 and O2 addition on biomass gasification in entrained flow reactor conditions: Experiments and modelling. Fuel 2016; 166:166, each incorporated herein by reference in their entirety.
The use of a catalyst is another interesting aspect of gasification of biomass/coal. Garcia et al. studied catalytic performance of Ni/Al2O3 on CO2 gasification of pine sawdust. See Garcia L, Salvador M L, Arauzo J, Bilbao R. CO2 as a gasifying agent for gas production from pine sawdust at low temperatures using a Ni/Al coprecipitated catalyst. Fuel Process Technol 2001; 69:157, incorporated herein by reference in its entirety. The experimental results indicated that the presence of Ni/Al2O3 enhances CO and H2 concentrations in the produced gas. Billaud reported that CO2 and H2O have a significant influence on the char conversion. However, at atmospheric condition CO2 has minimum effects on the gasification process.
Although the experimental works are important to understand the required reaction conditions of gasification process, they are time-consuming and expensive in terms of investment cost and consumable materials. See Masmoudi M A, Halouani K, Sahraoui M. Comprehensive experimental investigation and numerical modeling of the combined partial oxidation-gasification zone in a pilot downdraft air-blown gasifier. Energy Conyers Manage 2017; 144:34, incorporated herein by reference in its entirety.
In this regard, thermodynamic equilibrium model analysis is faster and economically more attractive than the experimental investigation for studying gasification process. See Adnan et al., A thermodynamic modeling approach, Int J Hydrogen Energy 2017 (2017); Adnan et al. (2018); Fortunato B, Brunetti G, Camporeale S M, Torresi M, Fornarelli F. Thermodynamic model of a downdraft gasifier. Energy Conyers Manage 2017; 140:281; and Han J, Liang Y, Hu J, Qin L, Street J, Lu Y, et al. Modeling downdraft biomass gasification process by restricting chemical reaction equilibrium with Aspen Plus. Energy Conyers Manage 2017; 153:641, each incorporated herein by reference in its entirety.
An appropriate thermodynamic simulation can be useful to achieve the optimum experimental operating conditions with high accuracy. For example, the inventors developed a thermodynamic model to find the conditions of a modified moving bed downdraft gasifier. Adnan et al., A thermodynamic study by including tar, Int. J. Hydrogen Energy (2017). Renganathan et al. used a thermodynamic model to study the gasification performance of carbonaceous feed stocks using CO2, O2 and steam as the gasifying agents. See Renganathan T, Yadav M V, Pushpavanam S, Voolapalli R K, Cho Y S. CO2 utilization for gasification of carbonaceous feedstocks: A thermodynamic analysis. Chem Eng Sci 2012; 83:159, incorporated herein by reference in its entirety. Chaiwatanodom et al. conducted a thermodynamic model analysis to investigate the CO2 gasification of biomass using a CO2 recycle option. See Chaiwatanodom P, Vivanpatarakij S, Assabumrungrat S. Thermodynamic analysis of biomass gasification with CO2 recycle for synthesis gas production. Appl Energ 2014; 114:10, incorporated herein by reference in its entirety. To the best of our knowledge, there is no detail thermodynamic modeling study reported in the open literature dealing with the integrated microalgae biomass and coal gasification.
In view of the numerous relevant variables and the complexity of selecting an appropriate combination of feedstocks and process conditions, the present inventors aimed at investigating the performance of an integrated co-gasification of microalgae and coal using an equilibrium model. In addition a thermodynamic model was developed using Aspen Plus. As feedstocks, Nannochloropsis oculata (N. oculata) microalgae biomass and Indonesian low-rank brown coal were used. The combined use of biomass and coal with CO2 recycling option offers the opportunity of using abundantly available coal with minimum CO2 emission.
The model permitted the inventors to determine which process parameters critically affect efficient production of syngas with a low content of CO2 as well as the advantageous operating conditions of co-gasification.BRIEF SUMMARY OF THE INVENTION
An efficient process for co-gasifying or gasifying low grade coal and biomass is provided. This process is based on an integrated co-gasification of coal and biomass simulation model. It includes three subprocesses: (i) gasification, (ii) reforming and (iii) CO2 absorption. The process as modeled using the simulation exhibited a good accuracy when compared to experimental values obtained under the same operating conditions.
In co-gasification evaluation, a low-rank coal and Nannochloropsis oculata microalgae biomass were considered as feedstocks. The parametric study was carried out using various biomass to coal ratios at different pressures. The performance of the overall process was evaluated in terms of syngas composition, gasification system efficiency (GSE) and cold gas efficiency (CGE). The reforming and CO2 absorption steps enabled the process providing high purity syngas.
The increase of biomass/coal ratio enhanced GSE while decreased CGE.
High pressure operation was found to be unfavorable for producing high quality syngas as the increase of pressure affected the gasification.
Overall, the co-gasification of biomass/coal is a promising approach to utilize low-value coal and biomass feedstocks to produce high value syngas and contributes to minimization of greenhouse gas emissions.
Embodiments of the invention include, but are not limited to the following.
A process for producing syngas that comprises, consists essentially or consists of: co-gasifying a feedstock comprising low rank coal and a microalgae biomass at a temperature of about 700, 750, 800 to 850° C. with a gasification agent comprising at least >21, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95 vol. % oxygen to produce gasified intermediates; reforming the gasified intermediates to produce syngas; and removing carbon dioxide from the syngas, thereby producing syngas comprising hydrogen and carbon monoxide. However, in some embodiments the co-gasification and/or reforming temperature may range from 500, 600, 700, 800, 900, 1,000, 1,100, 1,200 or >1,200° C. (or any intermediate value within this range).
In some embodiments, the mixed feedstock may be heated at a rate from about 10, 20, 30, 40, to about 50° C./min and/or the co-gasification can be performed using a gasifier (e.g., O2, CO2 and/or H2O) supplied at a flow rate ranging from about 50 to 300 mL/min.
In other embodiments, a steam to carbon ratio can vary from 0.0 to 2.0, for example, from 0.0, >0.0, 0.01, 0.02, 0.05, 0.1, 0.2, 0.5, 1, 1.2, 1.5, <2, to 2 or any intermediate value within this range.
Gasification may be conducted in a counter-cured fixed bed gasifier, a co-current fixed bed gasifier, a fluidized bed reactor, an entrained flow gasifier or a plasma gasifier or other suitable gasifier. Gasifiers are known in the art and are incorporated by reference to https://_en.wikipedia.org/wiki/Gasification (last accessed Mar. 7, 2019).
The temperature of the reformer unit is about 800° C., for example, from about 750, 775, 800, 825, to about 850° C.
Advantageously this method may be used with a low grade coal feedstock such as Indonesian coal, its compositional equivalents or other low grade coals as well as with aquatic biomass such as Nannochloropsis oculata microalgae biomass or compositional equivalents of this biomass. A problem of the gasification of algal biomass and low grade coal is the high CO2 concentration in the syngas.
Among its other advantages, the invention includes a CO2 absorber to remove CO2 from the syngas stream. The product of CO2 absorber is high-purity CO2 and high quality syngas in term of syngas composition.
The process is advantageously practiced using a biomass/coal (“B/C”) ratio ranging from about 0.75 to about 1, for example, 0.7, 0.75, 0.8, 0.85, 0.9, 0.95, <1 or 1.0.
The co-gasification step of this method can advantageously use oxygen as a co-gasifier, for example, air or a gasifier enriched in oxygen, such as one containing >21, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95 or >95 vol. % oxygen. Preferably, co-gasification occurs with lower than atmospheric concentration of nitrogen, for example <78 vol. % including no more than 1, 2, 5, 10, 20, 30, 40, 50, 60, 70, 75 or 78 vol. % nitrogen.
Co-gasification may also occur in the presence of oxygen, H2O or CO2 or a mixture of two or three of these.
Co-gasification and reforming during the process as disclosed herein may occur at a pressure of 1, 2, 3, 4, 5, 10, 20, 30, 40 or 50 bar (or any intermediate value within this range). Preferably as explained herein, the pressure is about 1 bar.
In one embodiment of the process disclosed herein the O2 equivalence ratio (ER) ranges from 0 to 0.4, the B/C ratio ranges from 0.75 to 1 and the co-gasification agent is at least 80 vol. % oxygen containing less than 5 vol. % nitrogen.
In another embodiment of the invention, the B/C ratio, pressure, S/C ratio, CO2 to fixed carbon in the biomass ratio (“CO2:C molar ratio”), and O2 equivalence ratio (ER) are selected to provide a gasification system efficiency (“GSE”) ranging from 0.8 to 0.99. Co-gasification may also be performed at 0.9 to 1.1 bar with a steam:carbon (S/C) ratio of 0.9 to 1.1, a CO2:C molar ratio of 0.9, 0.95, 1.00, 1.05 to 1.1, and an equivalence ratio (ER) of 0.00 to 0.40. Advantageously, this embodiment may be performed where gasification is performed at about 1 bar with a steam:carbon (S/C) ratio of about 1, a CO2:C molar ratio of about 1 and an O2 equivalence ratio (ER) of about 0.00.
In another embodiment of this process, the B/C ratio, pressure, S/C ratio, CO2:C ratio, and O2 equivalence ratio (ER) are selected to provide a cold gas efficiency (“CGE”) ranging from 0.3 to 0.5. Advantageously, a biomass/coal ratio of 0.00 at no more than 1-2 bar with an S/C ratio of 0.00 a carbon dioxide:carbon ratio of 0.9 to 1.1 and an O2 equivalence ratio (ER) of 0.31 to 0.41 is used. Preferably, the biomass/coal ratio is about 0.00, at about 1 bar with an S/C ratio of about 0.00 a CO2:C molar ratio of about 1 and an O2 equivalence ratio (ER) of about 0.36.
In preferred embodiments, during or after co-gasification ash and unconverted char are removed from the co-gasified material.
The process as described herein also removes CO2 from the reformed co-gasified product. This may be accomplished using methods and equipment known in the art include, but not limited to contacting the syngas using a membrane that separates CO2 from syngas or by using a chemical adsorbent for CO2. Preferably, a Ca-based CO2 absorbent, such as one supplying exothermic heat, is not used to remove the carbon dioxide.
Another embodiment of the invention is directed to apparatus configured to perform the processes disclosed herein. The apparatus includes at least one input line for carbon dioxide (10), H2O (30), O2 (60), and biomass and coal feed (80), a gasifier (GSR)(100), a cyclone (CYL)(200), a reformer (RFM)(300), CO2 absorber (ABR)(400), an output line for carbon dioxide (440), and an output line for syngas (470); wherein the input lines input oxygen, H2O, carbon dioxide and biomass and coal feed to the gasifier, the gasifier is connected to the cyclone which is connected to the reformer, which is connected to the CO2 absorber which has an output line or port for syngas from which CO2 has been removed.
This apparatus may also include CO2 line feeds through a CO2 compressor (CP-1)(20), the H2O line feeds water through a pump (PMP-1)(40) and boiler (BL1)(50), the O2 line feeds through a compressor (CP-2)(70) and/or the biomass and coal-feed (80) feeds via a solid feeder system; and/or the absorber (ABR)(400) receives syngas from the reformer (RFM)(300) and feeds CO2 to a cooler (CR-1)(410) and a compressor for the CO2 product (CP-3)(420) which is linked to a second cooler (CR-2)(430) that provides an outward CO2 feed (440); and the absorber (ABR)(400) receives syngas from the reformer (RFM)(300) and feeds non-CO2 components of the syngas to a turbine (TR)(450) which feeds syngas to a third cooler (CR-3)(460). One embodiment of this apparatus is depicted by
Another embodiment of the invention is directed to a method for producing syngas from Indonesian coal or an equivalent low grade coal and from Nannochloropsis oculata microalgae biomass or an equivalent biomass comprising feeding a mixture of the coal and the biomass and a gasifying agent comprising oxygen, H2O and/or CO2 into the apparatus as disclosed herein gasifying the mixture, reforming the mixture, and removing CO2 from the reformed mixture.
The foregoing paragraphs have been provided by way of general introduction, and are not intended to limit the scope of the following claims. The described embodiments, together with further advantages, will be best understood by reference to the following detailed description taken in conjunction with the accompanying drawings.
A more complete appreciation of the disclosure and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawings below.
Mixed feedstocks of N. oculata and Indonesian coal having different compositions were used and the composition or properties of these feedstocks are presented in Table 1.
The proximate composition of a feedstock biomass includes, but is not limited to, a moisture content ranging from 5, 6, 7, to 8 mass %, volatile matter content ranging from 60, 65, 70, 75, 80, 85, or 95 mass %, fixed carbon content ranging from 6, 6.5, 7, 7.5, 8, 8.5, 9, or 9.5 mass %, and an ash content ranging from 5, 5.5, 6, 6.5, 7, 7.5 to 8 mass %. The ultimate composition of a biomass feedstock includes, but is not limited to, a content of C (carbon) ranging from 35, 40, 45, 50, to 55 mass %; a content of H (hydrogen) ranging from 4, 5, 6, to 7 mass %, a content of O (oxygen) ranging from 35, 40, 45, 50, to 55 mass % and a HHV, MJ/kg ranging from 12, 13, 14, 15, 16, 17, 18 to 19. These ranges include all intermediate values and subranges.
Other types of biomass which are substantially equivalent in composition to N. oculata biomass, such as a biomass having not more than about 1, 2, 5, 10, 15, or 20% difference in any of the values described in Table 1 for N. oculata biomass may also be employed. For example, biomass obtained from other species of Nanochloropsis such as N. gaditana, N. granulate, N. limnetica, N. oceanica, N. oculata or N. salina, may be used in some embodiments.
The proximate composition of a feedstock coal includes, but is not limited to, a moisture content ranging from 8, 9, 10, 11, 12, 13 or 14 mass %, a volatile matter content ranging from 30, 35, 40, 45, 50 to 55 mass %, a fixed carbon content ranging from 30, 35, 40, 45, to 50 mass %, and an ash content ranging from 6, 6.5, 7, 7.5, 8, 8.5, 9 to 9.5 mass %. The ultimate composition of a coal feedstock includes, but is not limited to, a C (carbon) content ranging from 55, 60, 65, 70, 75, 80, to 85 mass %; a content of H (hydrogen) ranging from 4, 4.5, 5, 5.5, 6, to 6.5 mass %, a content of O (oxygen) ranging from 15, 20, 25, to 30 mass % a N (nitrogen) content ranging from 0, to >0, to 0.1, 0.2, 0.3, 0.5 to 0.6 mass % and S (sulfur) content ranging from 0, >0, 0.2, 0.5, 1, 2, 3, 4 or 5 mass % and a HHV, MJ/kg ranging from 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28 to 29. These ranges include all intermediate values and subranges. Other types of coal which are substantially equivalent in composition to Indonesian coal, such as a coal not more than about 1, 2, 5, 10, 15 or 20% difference in one or more values described in Table 1 for Indonesian coal may also be employed. In some embodiments other types of coal, such as anthracite, bituminous, subbitumous, or lignite coals may be used in combination with N. oculata biomass.
Low rank coal may have a moisture content ranging from about 11.1, 12, 15, 20, to 22.33 wt %, volatile matter content ranging from about 38.05, 39, 40, 41, 42, 43 to about 43.46 wt %, fixed carbon ranging from about 37.47, 38, 39, 40, 41, to 42.08 wt % and ash content ranging from about 0.9, 1, 2, 3, 4, 5, 6, 7, to 7.8 wt %. Low rank coal may having a higher heating value (HHV) ranging from about 5038, 5050, 5100, 5150, 5200, 5300, 5400, 5500 to 5613 kcal/kg. These ranges include all intermediate values and subranges.
The low rank coal is a fossil fuel. The direct utilization of low rank coal (i.e, by combustion) leads to CO2 emission to the environment. However, low rank coal has relatively higher value of calories as compared to microalgae biomass. The gasification and reforming process favors high temperature. Therefore, a combination of both can provide superior performance in term of syngas composition and the amount of CO2 emission. For example, syngas produced according to the invention may have a content of H2 ranging from about 20, 25, 30, to about 35 vol. % H2, about 50, 55, 60, 65 to about 70 vol. % CO, 0.0, >0.0, 0.1, 0.2, 0.3, 0.4, or >0.4 vol. % CH4, and 0. >0, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 25, 30, 35, 40, to about 45 vol. % CO2 or any intermediate value or subrange within these ranges. The simulation was based on CO2 composition ranges between 0.00 to 0.45 vol.
This favorably compares to prior art methods which produce substantially more CO2 such as those of Alghurabie et. al. (2013) Fluidized bed gasification of Kingston coal and marine microalgae in a spouted bed reactor, Chemical Engineering Research and Design, reported CO2=51-63%, CO=26-43%, CH4=3-6%, H2=12-21%; and Kaewpanha et. al. (2014) Steam co-gasification of brown seaweed and land-based biomass, Fuel Processing Technology, reported CO2=6-16%, CO=8-18%, CH4=1-2%, H2=10-27%.
In some embodiments, the composition of H2, CO2 and CO after passage through the CO2 removal unit can range from 0.00 to 0.28, 0.21 to 0.56, and 0.00 to 0.45 by volume, respectively.
As shown by the block diagram in
A mixed feed stock is fed to the gasifier (GSR) through a solid feeder system which can handle solid feed at high-pressure conditions; see. Adnan et al. (2018) which is incorporated herein by reference.
The steam is obtained by feeding boiler feed water (BFW) into the boiler (BLI) using a BFW pump (PMP-1).
The boiler (BLI) produces steam at desired pressure which is sent to the gasifier (GSR).
The other gasifying agents, including CO2 and O2, are supplied to the gasifier (GSR) from a CO2 compressor (CP-1) and an O2 compressor (CP-2), respectively.
In the gasifier (GSR) the feedstocks interact with the gasifying agents—steam, O2 and CO2—to produce both gaseous and solid product, as described by following set of chemical reactions:
Partial oxidation C+½O2↔CO ΔH2980=−111 MJ/kmol (1)
Boudouard reaction C+CO2↔2CO ΔH2980=+172 MJ/kmol (2)
Steam reforming C+H2O↔CO+H2 ΔH2980=±131 MJ/kmol (3)
Methane formation C+2H2↔CH4 ΔH2980=−74 MJ/kmol (4)
Hydrogen combustion H2+½O2↔H2O ΔH2980=−484 MJ/kmol (5)
CO combustion CO+½O2↔CO2 ΔH2980=−284 MJ/kmol (6)
Water-gas shift reaction CO+H2O↔CO2+H2 ΔH2980=−42 MJ/kmol (7)
Methane-steam reforming CH4+H2O↔CO+3H2 ΔH2980=+206 MJ/kmol (8)
Methane-CO2 reforming CH4+CO2↔2CO+2H2 ΔH2980=+247 MJ/kmol (9)
Further description of these chemical reactions and associated equipment is incorporated by reference to Adnan et al., Enhancement of hydrogen production in a modified moving bed downdraft gasifier—A thermodynamic study by including tar. Int J Hydrogen Energy (2017).
The gasified products are sent to the cyclone (CYL) to remove solids including ash and unconverted char from the gaseous products.
After separation, the gas stream is then directed to the reformer (RFM) and the solid products are disposed out of the system.
In the reformer (RFM), CO and H2 concentrations in the gaseous products are further enhanced by both methane-steam reforming (Eq. 8) and methane-CO2 reforming (Eq. 9) reactions.
The CO/H2 enriched gaseous product is then directed to the CO2-absorber (ABR) to reduce the CO2 concentration.
The separated CO2 from the CO2-absorber (ABR) is passed through a series of unit operations, including cooler (CR-1) and CO2-compressor (CP-2) to reduce its temperature and compress to the desired levels.
The high quality gaseous products—mainly H2 and CO—from the CO2-absorber (ABR) are expanded and cooled to atmospheric conditions using a gas turbine (TR) and by a syngas cooler (CR-3).
Specific process conditions include those described in the Examples as well as the following. Initially, feedstocks, boiler feed water, CO2 and O2 may be at ambient or room temperature, advantageously between 15, 20, 25, 30, 35, 40, 45 and 50° C. and preferably about 25° C. Steam temperature may range from 100, 150, 200, 250, 300, 350, 400 or >400° C., advantageously about 300 to 400° C. and preferably about 350° C. Gasifier temperature can range from 500, 550, 600, 650, 700, 750, 800, 850, 900, 1,000, 1,050, to 1,100° C., advantageously from about 650 to 900° C. and preferably from about 700 to 850° C. Reformer temperature can range from 600, 650, 700, 750, 800, 850, 900, 1,000, 1,050, 1,100, 1,050, to 1,200° C., advantageously from about 700 to 900° C. and preferably from about 750 to 850° C. Pressure in the gasifier and/or reformer can range from <1, 1, 2, 5, 10, 20, 30, 40, 50 or >50 bar, advantageously from about 1 to 5 bar, and preferably about 1 bar. Pump, compressor and turbine efficiencies may be selected by those skilled in the art are generally at least 60, 65, 70, 75, 80, 85, 90, 95 or >95% efficient. All intermediate values and subranges are included in the ranges above.
The integrated biomass and coal gasification simulation model was developed in Aspen Plus based on Gibbs free energy minimization approach. The minimization of Gibbs free energy is a well-known technique for performance analysis of gasification process; see Adnan et al., Feed compositions and gasification potential of several biomasses including a microalgae: A thermodynamic modeling approach. Int J Hydrogen Energy 2017; Renganathan et al. (2012), incorporated by reference.
The feedstock of the gasification is considered as the non-conventional element in this model. The gasifying agents including steam, CO2 and O2 are considered as the conventional elements. The gasification product consists of three type of element in the Aspen Plus, including conventional element (the gaseous product), non-conventional element (the ash) and ci-solid element (the unconverted char). The present simulation considered the Peng-Robinson equation of state (EoS) as it provides good accuracy for simulation of gasification; see Adnan et al., Feed compositions and gasification potential of several biomasses including a microalgae: A thermodynamic modeling approach. Int J Hydrogen Energy 2017; Adnan et al., Enhancement of hydrogen production in a modified moving bed downdraft gasifier—A thermodynamic study by including tar. Int J Hydrogen Energy (2017). On a clean power generation system with the co-gasification of biomass and coal in a quadruple fluidized bed gasifier. Bioresource Technology 2017; 235:113, are each incorporated herein by reference in their entirety.EXAMPLES
A 100 kg/h of feed stock was used in all simulation runs. Both the gasifier (GSR) and reformer (RFM) are maintained at constant temperatures in order to minimize the kinetic limitation; see. Renganathan et al. (2012) incorporated by reference.
The gasification process is simulated using two blocks including RYield and RGibbs. The RYield represents the pyrolysis process, converting the feedstock (non-conventional element) into the conventional elements (H2, CO, CO2, CH4, H2O O2, and N2,) and ci-solid element (char).
An external FORTRAN subroutine is embedded to Aspen Plus to describe the reactions in the RYield. The RGibbs facilitates the gasification reactions as described herein.
The cyclone in front of gasifier is defined using SSplit block, to remove the solids (ash and unconverted char) from the syngas.
The reformer unit, represent by the REquil block, enhances the H2 and CO concentrations by facilitating methane-steam reforming (Eq. 8) and the methane-CO2 reforming (Eq. 9) reactions.
The quality of the syngas is further upgraded by reducing the CO2-concentration in the CO2-absorber with 90% CO2 removal. The calculation of the CO2-absorber is developed by using an external Microsoft Excel subroutine.
The high-purity CO2 is sent to the cooler/compressor block to compress it to 80 bar. The compressed high-purity CO2 is then heated to 250° C. using a heater.
The high quality syngas is expanded using a turbine block into the atmospheric pressure.
The present simulation also contemplates including: (i) N2 and ash which are considered as the inert materials, (ii) char which consists of pure carbon, (iii) a minimum mass transfer limitation and (iv) an insignificant pressure drop through the process.
The detailed parameters for the simulation model are tabulated in Table 2
The performance of the integrated co-gasification system is determined based on the (i) concentration of the desired components (CO and H2), (ii) gasification system efficiency (GSE), and (iii) cold gas efficiency (CGE).
For performance assessment, the dry gas composition is selected as the basic composition. The overall performance of the integrated co-gasification system is reflected by the GSE, which is defined in Eq. (10).
where, m, LHV, W and Q represent the mass flow rate, the lower heating value, the energy rate and the heat rate, respectively. The subscript syg and fds are the syngas and the feed stock, respectively. The subscript gsr, rfm, bli, and abr represent the gasifier, the reformer, the boiler and the absorber, respectively. The subscript cp-1, and cp-3 correspond to the compressor for the CO2 gasifying agent and the CO2 product, respectively, while the subscript cp-2 represents the O2 compressor for gasifying agent. The subscript tr, cr-1, cr-2 and cr-3 are the syngas turbine, the cooler-1, the cooler-2 and the cooler-3, respectively.
In order to upgrade the gasification performance, pure O2 (95% purity) is selected for gasifying agent instead of air due to its ability to bring higher gasification temperatures as compared to gasification with air. The present gasification process consumes about 30 kWh of energy for production of a ton of O2. In addition, the CO2 absorber requires about 3 MJ of energy per ton CO2 absorbed. CO2 absorbers are known and are incorporated by reference to Hussain A, Follmann M, Melin T, Hagg M B. CO2 removal from natural gas by employing amine absorption and membrane technology—A technical and economic analysis. Chem Eng J 2011; 172:952.
CGE represents the conversion of energy content in the feedstock to the usable energy in terms of heating value of the syngas. It is defined by the ratio of recoverable energy from the syngas to the energy of the feedstock and steam enthalpy, as defined by Eq. (15).
where, Hste and mste are steam enthalpy and mass flow rate of steam.
The H2 and CO compositions in the syngas are used as the main parameters for validation. Earlier studies have been considered as references for benchmarking the accuracy of the present study. In these studies the models were developed in Aspen Plus simulating the gasification of solid fuels. The simulations accurately predicted the experimental syngas compositions under similar reaction conditions; see Adnan M A, Hossain M M. Gasification of various biomasses including microalgae using CO2—A thermodynamic study. Renew Energ 2018, and Chaiwatanodom et al. (2014) both incorporated by reference. For the present disclosure, the operating conditions and the properties of the feed are similar to those considered in both Adnan and Hossain and Chaiwatanadom. In addition, the gasifying agents used (steam, O2 and CO2) are common to those in the above references.
Table 3 compares the syngas compositions of the present disclosure with those reported in Adnan and Hossain and Chaiwatanadom et al. under same reaction temperatures. The relative errors of the present results for CO and H2 (syngas) concentrations are lower than 6% indicating that good agreement with Adnan and Hossain and Chaiwatanadom et al.
The compositions of the syngas from the present disclosure at 800-1200° C. are also close to the syngas compositions as reported in other studies. Adnan et al., Enhancement of hydrogen production in a modified moving bed downdraft gasifier—A thermodynamic study by including tar. Int J Hydrogen Energy (2017); and Susanto et al. (1996).
The inventors selected a non-adiabatic reaction condition for all processes. The temperature of main reactors including gasifier (GSR) and reformer (RFM) were maintained at 973 K (700° C.) and 1073 K (800° C.), respectively. A discussion of the parametric study is presented herein, including the model description.
The molar flow rates of the feed and the product streams of the four main process in the integrated co-gasification system are shown in
In the reforming unit, methane reacted with steam and CO2 in methane-steam reforming reaction Eq. (8) and methane-CO2 reforming reaction Eq. (9), respectively, producing an additional amount of CO and H2.
The contribution of the methane reforming reactions are confirmed by the increase of CO and H2 flow rates in the product stream as depicted in
As a consequence, CO2 and CH4 in the feed stream were consumed, which was reflected in the decreased flow rates of CO2 and CH4 in the product stream. The H2 and CO compositions of the syngas further increased at the outlet of CO2 absorption unit (
The use of H2O, O2 and CO2 as gasifying agents improves the syngas quality. The selection of these gasifying agents (H2O, O2 and CO2) also helps minimize the NOx formation by avoiding the contact between nitrogen and the gasified products as usually observed in gasification using air.
On the other hand, the use of microalgae biomass also minimizes SOx emission, as its sulfur content is significantly lower than that of coal. Consequently, the SOx concentration in the syngas is significantly lower than the allowable SOx concentration outlined in the US EPA regulations.
The O2 equivalence ratio (ER ratio) is defined as the weight ratio of actual O2 to feed ratio per stoichiometric O2 to feed ratio. The gasifying agents (steam, CO2 and O2) have significant influence on the gasification performance. The use of pure O2 as the gasifying agent provides higher gasification temperature as compared to air. The influence of oxygen on performance of the integrated gasification process was investigated by introducing various amount of O2 to the gasifier from an O2 equivalence ratio (ER) of 0.0 to 1.0. The feed flow rate and steam to carbon molar ratio (S/C ratio) maintained at 100 kg/h and unity, respectively. At this stage, steam and CO2 were introduced with a constant CO2:C of unity.
The use of pure O2 requires higher energy for O2 separation (from air) as compared to the use of air. Tijmensen et al. (2002). This energy for O2 purification was taken into account in overall performance analysis.
It can be seen in
The biomass/coal (B/C) ratio also has a considerable influence on the composition of the syngas. As it can be observed in
As it can be seen in
The single phase reaction that occurs at high O2 equivalence ratio (ER) is mainly responsible for minimal change given the complete carbon conversion already has been achieved. Indeed, the pressure has stronger effect on the solid-gas reaction as opposed to the gas-gas reaction due to minimum mass transfer inference. A similar trend is also found in the co-gasification using the mixed feed stock at other B/C ratios (B/C ratios=0.0, 0.25, 0.50 and 0.75). These findings showed strong effect of pressure at low O2 equivalence ratio (ER) and minimal effect of pressure at high O O2 equivalence ratio (ER) on gasification performance.
The O2 equivalence ratio (ER) significantly influenced the GSE of the gasification system, as depicted in
The O2 equivalence ratio (ER) has a great deal of influence on the CGE, as depicted in
The effect of steam on gasification performance was conducted by varying the steam flow rate at a constant feed flow rate and O2 equivalence ratio (ER) of 100 kg/h and 0.36, respectively. The steam to carbon ratio (S/C ratio) is defined as the molar ratio of steam to carbon in the feed stock.
The syngas composition varied as the pressure varied from 1 bar to 25 bar, and then to 50 bar, as seen in
Again, the B/C ratio has a considerable effect on the syngas composition. As it can be seen in
One can see a different trend of CO concentration in gasification at 1 bar and 25 bar in
It can be clearly seen in
A similar pattern was found in gasification with other B/C ratios (i.e., B/C ratio of 0.00, 0.25, 0.50 and 0.75). Indeed, the B/C ratio significantly influenced the GSE of the gasification system. For instance, in the gasification at 1 bar, the GSE augmented from 0.66 to 0.99 when the B/C ratio was increased from 0.00 to 2.00. This is due to the fact that higher energy for CO2-absorption was found on the lower B/C ratio. The difference of the GSE pattern was found at 1 bar and 25 bar, respectively (
Again, the CGE was slightly affected by the S/C ratio in gasification at 1 bar, as indicated in
As shown herein, an integrated biomass and coal gasification process has been developed using Aspen Plus, combining gasification, reforming and CO2-absorption to produce a high quality syngas and high-purity CO2. Indonesian low-rank coal and N. oculata microalgae biomass with different B/C ratios were used as feed stocks while steam, CO2 and O2 were used as gasifying agents. Aspen Plus software is known in the art and incorporated by reference to https://www.aspentech.com/products/engineering/aspen-plus/ (last accessed Mar. 6, 2019).
This process provides several advantages. The reforming and CO-absorption steps were able to upgrade the syngas quality in term of high concentration of CO and H2, and minimal concentration of CO2, respectively. The increase of pressure diminished the performance of the gasification (CGE, GSE, syngas composition). The increase of B/C ratio has a positive effect on the GSE while an adverse effect on the CGE. The highest GSE (0.99) was exhibited on the gasification of N. oculata (B/C ratio=0.00) at 1 bar with the S/C ratio of 0.00, CO2:C molar ratio of unity and O2 equivalence ratio (ER) of 0.36. The highest CGE of 0.49 was observed in the gasification of Indonesian coal at 1 bar with the S/C ratio of 1.00, CO2:C molar ratio of unity and O2 equivalence ratio (ER) of 0.00. The synergetic effect of Indonesian coal and N. oculata exhibited an optimum gasification performance. Moreover, the inventors work provided several other surprising advantages including (i) utilizing CO2 as a gasifying agent, (ii) producing superior quality syngas and (iii) providing high purity CO2 for other uses such as methanol synthesis.
Terminology. Terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention.
The headings (such as “Background” and “Summary”) and sub-headings used herein are intended only for general organization of topics within the present invention, and are not intended to limit the disclosure of the present invention or any aspect thereof. In particular, subject matter disclosed in the “Background” may include novel technology and may not constitute a recitation of prior art. Subject matter disclosed in the “Summary” is not an exhaustive or complete disclosure of the entire scope of the technology or any embodiments thereof. Classification or discussion of a material within a section of this specification as having a particular utility is made for convenience, and no inference should be drawn that the material must necessarily or solely function in accordance with its classification herein when it is used in any given composition.
As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.
It will be further understood that the terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, steps, operations, elements, components, and/or groups thereof.
As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items and may be abbreviated as “/”.
Links are disabled by deletion of http: or by insertion of a space or underlined space before www. In some instances, the text or content available via the link on the “last accessed” date may be incorporated by reference.
As used herein in the specification and claims, including as used in the examples and unless otherwise expressly specified, all numbers may be read as if prefaced by the word “substantially”, “about” or “approximately,” even if the term does not expressly appear. The phrase “about” or “approximately” may be used when describing magnitude and/or position to indicate that the value and/or position described is within a reasonable expected range of values and/or positions. For example, a numeric value may have a value that is +/−0.1% of the stated value (or range of values), +/−1% of the stated value (or range of values), +/−2% of the stated value (or range of values), +/−5% of the stated value (or range of values), +/−10% of the stated value (or range of values), +/−15% of the stated value (or range of values), +/−20% of the stated value (or range of values), etc. Any numerical range recited herein is intended to include all sub-ranges subsumed therein.
Disclosure of values and ranges of values for specific parameters (such as temperatures, molecular weights, weight percentages, etc.) are not exclusive of other values and ranges of values useful herein. It is envisioned that two or more specific exemplified values for a given parameter may define endpoints for a range of values that may be claimed for the parameter. For example, if Parameter X is exemplified herein to have value A and also exemplified to have value Z, it is envisioned that parameter X may have a range of values from about A to about Z. Similarly, it is envisioned that disclosure of two or more ranges of values for a parameter (whether such ranges are nested, overlapping or distinct) subsume all possible combination of ranges for the value that might be claimed using endpoints of the disclosed ranges. For example, if parameter X is exemplified herein to have values in the range of 1-10 it also describes subranges for Parameter X including 1-9, 1-8, 1-7, 2-9, 2-8, 2-7, 3-9, 3-8, 3-7, 2-8, 3-7, 4-6, or 7-10, 8-10 or 9-10 as mere examples. A range encompasses its endpoints as well as values inside of an endpoint, for example, the range 0-5 includes 0, >0, 1, 2, 3, 4, <5 and 5.
As used herein, the words “preferred” and “preferably” refer to embodiments of the technology that afford certain benefits, under certain circumstances. However, other embodiments may also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the technology.
As referred to herein, all compositional percentages are by weight of the total composition, unless otherwise specified. As used herein, the word “include,” and its variants, is intended to be non-limiting, such that recitation of items in a list is not to the exclusion of other like items that may also be useful in the materials, compositions, devices, and methods of this technology. Similarly, the terms “can” and “may” and their variants are intended to be non-limiting, such that recitation that an embodiment can or may comprise certain elements or features does not exclude other embodiments of the present invention that do not contain those elements or features.
Although the terms “first” and “second” may be used herein to describe various features/elements (including steps), these features/elements should not be limited by these terms, unless the context indicates otherwise. These terms may be used to distinguish one feature/element from another feature/element. Thus, a first feature/element discussed below could be termed a second feature/element, and similarly, a second feature/element discussed below could be termed a first feature/element without departing from the teachings of the present invention.
Spatially relative terms, such as “under”, “below”, “lower”, “over”, “upper”, “in front of” or “behind” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures. It will be understood that the spatially relative terms are intended to encompass different orientations of the device in use or operation in addition to the orientation depicted in the figures. For example, if a device in the figures is inverted, elements described as “under” or “beneath” other elements or features would then be oriented “over” the other elements or features. Thus, the exemplary term “under” can encompass both an orientation of over and under. The device may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein interpreted accordingly. Similarly, the terms “upwardly”, “downwardly”, “vertical”, “horizontal” and the like are used herein for the purpose of explanation only unless specifically indicated otherwise.
When a feature or element is herein referred to as being “on” another feature or element, it can be directly on the other feature or element or intervening features and/or elements may also be present. In contrast, when a feature or element is referred to as being “directly on” another feature or element, there are no intervening features or elements present. It will also be understood that, when a feature or element is referred to as being “connected”, “attached” or “coupled” to another feature or element, it can be directly connected, attached or coupled to the other feature or element or intervening features or elements may be present. In contrast, when a feature or element is referred to as being “directly connected”, “directly attached” or “directly coupled” to another feature or element, there are no intervening features or elements present. Although described or shown with respect to one embodiment, the features and elements so described or shown can apply to other embodiments. It will also be appreciated by those of skill in the art that references to a structure or feature that is disposed “adjacent” another feature may have portions that overlap or underlie the adjacent feature.
The description and specific examples, while indicating embodiments of the technology, are intended for purposes of illustration only and are not intended to limit the scope of the technology. Moreover, recitation of multiple embodiments having stated features is not intended to exclude other embodiments having additional features, or other embodiments incorporating different combinations of the stated features. Specific examples are provided for illustrative purposes of how to make and use the compositions and methods of this technology and, unless explicitly stated otherwise, are not intended to be a representation that given embodiments of this technology have, or have not, been made or tested.
All publications and patent applications mentioned in this specification are herein incorporated by reference in their entirety to the same extent as if each individual publication or patent application was specifically and individually indicated to be incorporated by reference, especially referenced is disclosure appearing in the same sentence, paragraph, page or section of the specification in which the incorporation by reference appears.
The citation of references herein does not constitute an admission that those references are prior art or have any relevance to the patentability of the technology disclosed herein. Any discussion of the content of references cited is intended merely to provide a general summary of assertions made by the authors of the references, and does not constitute an admission as to the accuracy of the content of such references.
1: A process for producing a syngas, comprising:
- co-gasifying a feedstock comprising low rank coal and a microalgae biomass at a temperature of about 700 to 850° C. with a gasification agent comprising at least 90 vol. % oxygen, steam and CO2 based on a total volume of the gasification agent to produce a gasified intermediate;
- reforming the gasified intermediate to produce a syngas mixture; and
- removing carbon dioxide from the syngas mixture to thereby producing the syngas, wherein the syngas comprises hydrogen and carbon monoxide and is substantially free of carbon dioxide.
2. The process of claim 1, wherein the low rank coal is Indonesian coal.
3. The process of claim 1, wherein the biomass is Nannochloropsis oculata microalgae biomass.
4. The process of claim 1, wherein a biomass/coal (“B/C”) ratio in the feedstock ranges from about 0.75 to about 1.
5. The process of claim 1, wherein the co-gasifying occurs in the presence of no more than 5 vol % nitrogen based on a total volume of the gasification agent and/or in the presence of at least 95 vol. % oxygen based on a total volume of the gasification agent.
6. The process of claim 1, wherein the co-gasification occurs in the presence of oxygen, water and carbon dioxide.
7. The process of claim 1, wherein the co-gasification and reforming occur at a pressure of about 1 to 50 bar.
8. The process of claim 1, wherein the co-gasification and reforming occur at a pressure of about 1 bar.
9. The method of claim 1, wherein an O2 equivalence ratio (ER) ranges from 0 to 0.4, a biomass/coal (B/C) ratio ranges from 0.75 to 1 and the gasification agent is at least 90 vol. % oxygen containing less than 5 vol. % nitrogen each based on a total volume of the gasification agent.
10. The method of claim 1, wherein a biomass/coal (B/C) ratio, pressure, a steam:carbon (S/C) ratio, COQ to fixed carbon in the biomass (“CO2:C molar ratio”), and O2 equivalence ratio (ER) ratio provide a gasification system efficiency (“GSE”) ranging from 0.8 to 0.99.
11. The method of claim 1, wherein the c0-gasification is performed at 0.9 to 1.1 bar with a steam:carbon (S/C) ratio of 0.9 to 1.1, a CO2:C molar ratio of 0.9 to 1.1, and an O2 equivalence ratio (ER) of 0.00 to 0.40.
12. The method of claim 1, wherein the co-gasification is performed at about 1 bar with a steam:carbon (S/C) ratio of about 1, a CO2:C molar ratio of about 1 and an O2 equivalence ratio (ER) of about 0.00.
13. The method of claim 1, wherein the B/C ratio, pressure, S/C ratio, CO2/C ratio, and ER ratio provide a cold gas efficiency (“CGE”) ranging from 0.3 to 0.5.
14. The method of claim 1, wherein a biomass/coal ratio of 0.00, at a pressure of 1 to 2 bars with an S/C ratio of 0.00 a CO2:Cmolar ratio of 0.9 to 1.1 and an O2 equivalence ratio ER ratio of 0.31 to 0.41.
15. The method of claim 1, wherein the biomass/coal ratio is about 0.00, at a pressure of about 1 bar with an S/C ratio of about 0.00 a CO2:C molar ratio of about 1 and an O2 equivalence ratio ER ratio of about 0.36.
16. The method of claim 1, wherein co-gasifying further comprises removing ash and unconverted char from products of the co-gasification.
17. The method of claim 1, wherein removing the carbon dioxide from the syngas comprises contacting the syngas with a membrane that separates CO2 from the syngas mixture or by using a chemical adsorbent for CO2.
18. An apparatus configured to perform the process of claim 1, comprising:
- at least one input line for oxygen, H2O, carbon dioxide, and biomass and coal feed,
- a gasifier (GSR),
- a cyclone (CYL),
- a reformer (RFM),
- CO2 absorber (ABR), and
- an output line for syngas;
- wherein the O2, CO2 and H2O input lines are configured to input O2, CO2, and H2O into the gasifier and the and biomass and coal input line is configured to feed biomass and coal to the gasifier, and wherein the gasifier is connected to the cyclone which is connected to the reformer, which is connected to the CO2 absorber which is connected to the output line for syngas from which CO2 has been removed.
19. The apparatus of claim 18, wherein the CO2 input line feeds through a CO2 compressor (CP-1), the H2O input line is configured to feed water through a boiler (BL1), the O2 input line is configured to feed O2 through a compressor (CP-2) and/or the biomass and coal input line is configured to feed biomass and coal into the gasifier (GSR); and/or
- the absorber (ABR) is configured to receive syngas from the reformer (RFM) and is configured to feed CO2 to a cooler (CR-1) and to a compressor configured to receive CO2 product (CP-3) which is linked to a second cooler (CR-2) that is configured to provide an outward CO2 feed; and the absorber (ABR) is configured to receive syngas from the reformer (RFM) and configured to feed non-CO2 components of the syngas to a turbine (TR) which is configured to feed syngas to a third cooler (CR-3).
20. A method for producing a syngas from Indonesian coal or an equivalent low grade coal and from Nannochloropsis oculata microalgae biomass or an equivalent biomass comprising:
- feeding a mixture of the coal and the biomass and a gasifying agent comprising oxygen, H2O and/or CO2 into the apparatus of claim 18,
- gasifying the mixture,
- reforming the mixture, and
- removing CO2 from the reformed mixture.
Filed: Mar 22, 2019
Publication Date: Sep 24, 2020
Applicants: King Fahd University of Petroleum and Minerals (Dhahran), King Abdulaziz City for Science and Technology (Riyadh)
Inventors: Mohammad Mozahar HOSSAIN (Dhahran), Muflih Arisa Adnan (Dhahran)
Application Number: 16/362,127